Reconfigurable seismic sensor cable

ABSTRACT

Embodiments relate to a sensor cable that may be reconfigurable to have various combinations of seismic sensors. An apparatus may comprise a sensor cable and seismic sensors distributed throughout a volume of the sensor cable and along all three axes of the sensor cable, wherein the seismic sensors are assigned to sampling groups that are reconfigurable and not hardwired.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims the benefit of U.S. ProvisionalApplication No. 61/897,510, filed Oct. 30, 2013, entitled“Reconfigurable Seismic Streamer,” the entire disclosure of which isincorporated herein by reference.

BACKGROUND

Embodiments relate generally to seismic sensor cables (or simply “sensorcables”) for marine geophysical surveys. More particularly, embodimentsrelate to a sensor cable that may be reconfigurable to have variouscombinations of seismic sensors.

Techniques for marine geophysical surveying include seismic surveying,in which geophysical data may be collected from below the Earth'ssurface. Seismic surveying has applications in mineral and energyexploration and production to help identify locations ofhydrocarbon-bearing formations. Seismic surveying typically may beperformed using sensor cables, such as “streamers” that may be towedthrough a body of water or “ocean bottom cables” that may be located onthe water bottom. The sensors cables may include a plurality of seismicsensors, such as hydrophones, particle motion sensors, accelerometers,geophones, etc., disposed thereon at spaced apart locations along thelength of each cable. In a typical seismic survey, one or more seismicsources may be actuated to generate, for example, seismic energy thattravels downwardly through the water and into the subsurface rock.Seismic energy that interacts with interfaces, generally at theinterfaces between layers of rock formations, may be reflected towardthe surface and detected by the seismic sensors on the sensor cables.The seismic energy may be reflected when there is a difference inacoustic impedance between the layer above the interface and the layerbelow the interface. The detected energy may be used to infer certainproperties of the subsurface rock, such as structure, mineralcomposition and fluid content, thereby providing information useful inthe recovery of hydrocarbons.

Currently, a typical sensor cable may contain a limited quantity ofseismic sensors (e.g., hydrophones, particle motion sensors,accelerometers, geophones, etc.) distributed evenly or variably alongthe length of the streamer. Seismic sensors such as hydrophones may bearranged in various configurations along the sensor cable. FIG. 1illustrates an example sensor cable 10 that may comprise inline seismicsensors 12 disposed at spaced apart locations along a length of thesensor cable 10. The inline seismic sensors 12 may be arranged in whatis generally known as a “group-forming” technique. As illustrated, theinline seismic sensors 12 may be arranged in sampling groups 14 in whichthe signals recorded by the inline seismic sensors 12 in each group maybe combined or summed in various ways.

There may be drawbacks to the conventional group-forming technique. Forinstance, the sampling of locations assigned to the sampling groups 14or the sampling of the individual inline seismic sensors 12 may befixed. The inline seismic sensors 12 in the sampling groups 14 may bespaced at a fixed distance, typically at least about 60 cm. Moreover,the sampling distance is generally limited by the functionality of thehardware that connects the inline seismic sensors 12 in the samplinggroups 14.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention and should not be used to limit or define theinvention.

FIG. 1 shows a prior art sensor cable containing groups of inlineseismic sensors disposed at spaced apart locations.

FIG. 2 shows an example embodiment of a marine geophysical survey systemusing a reconfigurable sensor cable.

FIG. 3 shows an example embodiment of a film-based sensor.

FIG. 4 shows an example embodiment of a sensor strip of film-basedsensors.

FIG. 5 shows an example reconfigurable sensor cable that comprises aplurality of seismic sensors distributed throughout a volume of thesensor cable.

FIG. 6 shows an example reconfigurable sensor cable that comprises aplurality of seismic sensors distributed throughout a volume of thesensor cable.

FIG. 7 shows an example reconfigurable sensor cable that comprises aplurality of seismic sensors distributed throughout a volume of thesensor cable.

FIG. 8 is a three-dimensional view of the reconfigurable sensor cable ofFIG. 5.

FIG. 9 is a side view of a slice of the reconfigurable sensor cable ofFIG. 5.

FIG. 10 is a cross-sectional view of the reconfigurable sensor cable ofFIG. 5.

FIG. 11 shows an example reconfigurable sensor cable that comprises foursensor strips distributed throughout a volume of the reconfigurablesensor cable in a helical pattern.

FIG. 12 shows an example reconfigurable sensor cable that comprises twosensor strips distributed around the core of the reconfigurable sensorcable.

DETAILED DESCRIPTION

It is to be understood that the present disclosure is not limited toparticular devices or methods, which may, of course, vary. It is also tobe understood that the terminology used herein is for the purpose ofdescribing particular embodiments only, and is not intended to belimiting. All numbers and ranges disclosed herein may vary by someamount. Whenever a numerical range with a lower limit and an upper limitis disclosed, any number and any included range falling within the rangeare specifically disclosed. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. As used herein, the singular forms “a”, “an”, and “the”include singular and plural referents unless the content clearlydictates otherwise. Furthermore, the word “may” is used throughout thisapplication in a permissive sense (i.e., having the potential to, beingable to), not in a mandatory sense (i.e., must). The term “include,” andderivations thereof, mean “including, but not limited to.” The term“coupled” means directly or indirectly connected. If there is anyconflict in the usages of a word or term in this specification and oneor more patent or other documents that may be incorporated herein byreference, the definitions that are consistent with this specificationshould be adopted for the purposes of understanding this invention.

Embodiments relate generally to seismic sensor cables (or simply “sensorcables”), such as streamers or ocean-bottom cables, for marinegeophysical surveys. More particularly, embodiments relate to a sensorcable that may be reconfigurable to have various combinations of seismicsensors. One of the many potential advantages of the systems and methodsof the present invention, only some of which are disclosed herein, isthat the seismic sensors may be reconfigurable in various differentways, rather than hardwiring the seismic sensors into sampling groups.(See FIG. 5 for a more extensive discussion of reconfigurable samplinggroups.) For example, in response to a failure of one or more seismicsensors, contributions of adjacent seismic sensors may be reweighted incompensation of the failure. By way of further example, the samplingdistance after group forming may be changed without changing thehardware of the seismic sensors, particularly when using certain of theseismic sensors (e.g., film-based sensors). Additionally, several ordersof directional derivatives along or orthogonal to the sensor cable (orin other directions) may be determined. As would be understood by one ofordinary skill in the art with the benefit of this disclosure, similarpotential advantages exist when implementing reconfigurable seismicsensors with ocean bottom cables and streamers. Consequently, thediscussion below should be read to include both reconfigurable seismicocean bottom cables and reconfigurable seismic streamers.

Referring now to FIG. 2, a marine geophysical survey system 16 isillustrated in accordance with an example embodiment. In the illustratedembodiment, the marine geophysical survey system 16 may include a surveyvessel 18 that moves along the surface of a body of water 20, such as alake or ocean. The survey vessel 18 may include thereon equipment, showngenerally at 22 and collectively referred to herein as a “recordingsystem.” The recording system 22 may include devices (none shownseparately) for detecting and making a time indexed record of signalsgenerated by each of seismic sensors 24 (explained further below) andfor actuating a seismic source 26 at selected times. The recordingsystem 22 may also include devices (none shown separately) fordetermining the geodetic position of the survey vessel 18 and thevarious seismic sensors 24.

As illustrated, the survey vessel 18 (or a different vessel) may tow theseismic source 26 in the body of water 20. A source cable 28 may couplethe seismic source 26 to the survey vessel 18. The seismic source 26 mayinclude any of a variety of different types of sources capable ofimparting acoustic energy into the water, including, without limitation,a seismic air gun, a water gun, a vibrator, or an array of such devices,for example. At selected times, the seismic source 26 may be triggered,for example, by the recording system 22, to generate acoustic energy. Itshould be noted that, while the present example, shows only one seismicsource 26, the invention is applicable to any number of seismic source26 towed by the survey vessel 18 or any other vessel.

The survey vessel 18 may further tow a reconfigurable seismic streamer30. The reconfigurable seismic streamer 30 may be coupled to the surveyvessel 18 by way of a lead line 32. The reconfigurable seismic streamer30 may be towed in a selected pattern in the body of water 20 by thesurvey vessel 18 or a different vessel. The configuration of thereconfigurable seismic streamers 30 on FIG. 2 is provided to illustratean example embodiment and is not intended to limit the presentinvention. It should be noted that, while the present example, showsonly one reconfigurable seismic streamer 30, the invention is applicableto any number of streamers, some or all of which may be reconfigurableseismic streamers, towed by the survey vessel 18 or any other vessel.For example, in some embodiments, more than one reconfigurable seismicstreamer 30 may be towed by survey vessel 18 that may be spaced apartlaterally, vertically, or both laterally and vertically. “Lateral” or“laterally,” in the present context, means transverse to the directionof the motion of the survey vessel 18. Although not illustrated, marinegeophysical survey system 16 may optionally include hardware forconducting electromagnetic surveying. In some embodiments, marinegeophysical survey system 16 may include one or more ocean bottomcables, some or all of which may be reconfigurable ocean bottom cables.

The reconfigurable seismic streamer 30 may include seismic sensors 24that generate signals, such as electrical or optical signals, inresponse to detecting seismic energy emitted from the seismic source 26after the energy has interacted with the rock formations 34 below thewater bottom 36. Signals generated by the seismic sensors 24 may becommunicated to the recording system 22. In accordance with anembodiment of the invention, a geophysical data product may be produced.The geophysical data product may include processed geophysical dataobtained from one or more of the seismic sensors and may be stored on anon-transitory, tangible computer-readable medium. The geophysical dataproduct may be produced offshore (i.e. by equipment on a survey vessel)or onshore (i.e. at a facility on land) either within the United Statesor in another country. If the geophysical data product is producedoffshore or in another country, it may be imported onshore to a facilityin the United States. Once onshore in the United States, geophysicalanalysis, including further data processing, may be performed on thegeophysical data product.

As illustrated, the seismic sensors 24 may be distributed throughout avolume of the reconfigurable seismic streamer 30, including over andaround a surface of the reconfigurable seismic streamer 30. This may bean interior or exterior surface of the reconfigurable seismic streamer30. By way of example, the surface of the reconfigurable seismicstreamer 30 may be cylindrical or substantially cylindrical in shape. Insome embodiments, the seismic sensors 24 may be distributed along allthree axes of the reconfigurable seismic streamer 30. In someembodiments, the seismic sensors 24 may be distributed over a majorityof the surface of the reconfigurable seismic streamer 30, up to andincluding substantially fully covering the surface of at least a portionof the reconfigurable seismic streamer 30. The reconfigurable seismicstreamer 30 may include various distributions, arrangements, andconfigurations of the seismic sensors 24. The reconfigurable seismicstreamer 30 may increase robustness of the marine geophysical surveysystem 16, reduce operating cost, and increase data accuracy.

The seismic sensors 24 may be distributed throughout the reconfigurableseismic streamer 30 in a closer spacing than previously used in seismicsurveying wherein the sensors are spaced at regular (or semi-regular)locations. The term “spacing” with respect to the seismic sensors 24refers to the direct distance through the volume of the reconfigurableseismic streamer 30 between any one of the seismic sensors 24 and theclosest neighboring of the seismic sensors 24. For example, in contrastto conventional sensor spacing of about 60 centimeters, the seismicsensors 24 may have a spacing of about 50 centimeters or less. Inparticular embodiments, the seismic sensors 24 may have a spacing ofabout 10 centimeters or less and, alternatively, of about 5 centimetersor less.

In accordance with particular embodiments, the seismic sensors 24 may bedistributed at a much greater density on the reconfigurable seismicstreamer 30 by using specially designed sensors that enable distributionof the seismic sensors 24 throughout the volume of the reconfigurableseismic streamer 30. Examples of suitable seismic sensors 24 may includepiezoelectric sensors. As will be discussed in more detailed below withrespect to FIGS. 3-4, embodiments of the seismic sensors 24 may includefilm-based sensors (e.g., film-based sensor 38 on FIG. 3). Additionalexamples of suitable seismic sensors 24 may includemicroelectromechanical systems (“MEMS”) sensors. Examples of suitableMEMS sensors are described in more detail in U.S. Pat. No. 8,650,963,the disclosure of which is incorporated herein by reference.

The reconfigurable seismic streamer 30 may be referred to as“reconfigurable” because the seismic sensors 24 may not be hardwiredinto sampling groups, but can rather be combined in many different waysto provide a multitude of different sampling groups. In someembodiments, one or more of the seismic sensor 24 may not be initiallyincluded in a sampling group, but can be included in subsequentprocessing, for example, to replace other of the seismic sensors 24 thatmay have malfunctioned during use of the reconfigurable seismic streamer30. In one particular embodiment, the locations of the seismic sensors24 within and/or on the reconfigurable seismic streamer 30 may be known.For example, the locations of the seismic sensors 24 may be known duringthe manufacturing process of the reconfigurable seismic streamer 30. Asthe location of the seismic sensors 24 are known, signals from theseismic sensors 24 may be combined in various other ways than simplyhardwiring into sampling groups. In particular embodiments, signals fromall of the seismic sensors 24 may be transmitted to the survey vessel 18and then grouped as needed. Under certain operational considerations,data from one or more of the seismic sensors 24 in a particular samplinggroup may be excluded and replaced by reweighting contributions ofothers of the seismic sensors 24 in the particular sampling group. Insome embodiments, the sampling groups may be reconfigured, for example,to account for local rotation. In some embodiments, a sampling group ofthe seismic sensors 24 may be enlarged, for example, if noise levelsincrease or to replaced failed ones of the seismic sensors 24. Thesampling group may be enlarged, in some embodiments, by adding one ormore of the seismic sensors 24 that were not in the initial samplinggroup. In the event that one or more of the seismic sensors 24 faileither during manufacturing of the reconfigurable seismic streamer 30 orduring operation, the failed sensors may easily be compensated for byreweighting the contributions of the neighboring functioning sensors. Insome embodiments, reweighting of sensor contributions may be based onamplitude, time, or both with regards to frequency content. This mayallow a greater number of sensor failures in the sampling group beforethat particular group is considered bad. By way of example, two, five,ten, or even more of the seismic sensors 24 in a sampling group may failbut due to the large number of the seismic sensors 24 in each samplinggroup, the data from the failed sensors may be excluded as discussedabove.

Assigning and/or re-assigning the seismic sensors 24 to differentsampling groups may be accomplished using a computer system, which mayperform this reconfiguring of sampling groups either dynamically duringa geophysical survey or in subsequent processing of the obtainedgeophysical data. In some embodiments, the reconfiguring may occurbetween shots (i.e., sound bursts). The computer system may be acomponent of the recording system 22 on the survey vessel 18.Alternatively, the computer system may be located on a different vesselor onshore either within the United States or in another country, forexample, where the reconfiguring of the sampling groups occurs insubsequent processing after completion of the geophysical survey.

Moreover, the reconfigurable seismic streamer 30 may not be limited byhardware of the seismic sensors 24, particularly with film-basedsensors, in the sampling distance of a sampling group of the seismicsensors 24. By way of example, in common implementations today, thesampling groups typically have a sampling distance of 12.5 meters. Thesampling distance when used with reference to a sampling group typicallyrefers to the distance between the two of the sensors 24 in the samplinggroup with the greatest spacing. An example sampling distance (d) isshown on FIG. 1. However, by use of the disclosed techniques, smallersampling groups may be used, which may have lengths as small as 6.25meters or even smaller. In addition, the lengths of the sampling groupsmay be regular or irregular.

FIG. 3 illustrates a side, cross-sectional view of an example of afilm-based sensor 38 that may be used in accordance with presentembodiments. In particular, the film-based sensor 38 may be used as oneor more of the seismic sensors 24 shown on FIG. 2. The film-based sensor38 may be flexible and/or bendable. In particular embodiments, thefilm-based sensor 38 may be in the form of a sensor strip that can bewoven together with one or more additional film-based sensors 38 along astreamer (e.g., reconfigurable seismic streamer 30 on FIG. 2).

As illustrated, the film-based sensor 38 may include a film 40. Thefilm-based sensor 38 may further comprise a pair of conductive layers,e.g., upper conductive layer 42 and lower conductive layer 44, onopposing sides of the film 40. The upper conductive layer 42 and lowerconductive layer 44 may function as electrodes in the film-based sensor38. The film 40, upper conductive layer 42, and lower conductive layer44 may be coated on a protective sheet 46 with a protective coating 48disposed on the upper conductive layer 42. The configuration of thefilm-based sensor 38 shown on FIG. 3 is merely illustrative and use ofalternative configurations for the film-based sensor 38 is within thescope of the present disclosure.

In some embodiments, the film 40 may comprise a piezoelectric ceramic.Non-limiting examples of suitable piezoelectric ceramics include bariumtitanate, lead zirconate, lead titanate, and combinations thereof. Inaccordance with present embodiments, the film 40 may further comprise aviscoelastic polymer. By way of example, the film 40 may comprise amixture of the piezoelectric ceramic and the viscoelastic polymer. Inone particular embodiment, the viscoelastic polymer may have acompressibility that may be dependent upon a voltage of the viscoelasticpolymer. For example, the viscoelastic polymer may harden in a certainfrequency range and soften in an alternate frequency. In this manner,the viscoelastic polymer may be used to form a film 40 that issufficiently hard to function as a sensor for seismic surveying withoutundesired sound absorption while also being soft enough to be pliable.

In some embodiments, the upper conductive layer 42 and the lowerconductive layer 44 may include a variety of different conducivematerials. Without limitation, suitable conductive materials may includemetals, such as gold, platinum, silver, iridium, aluminum, molybdenum,ruthenium, titanium titride, iridium oxide, ruthenium oxide, lanthanumnickel oxide, metal oxides of these metals, and combinations thereof.The upper conductive layer 42 and the lower conductive layer 44 may bethe same conductive material or a different conductive material.

As illustrated, the film-based sensor 38 may further comprise aprotective sheet 46 and a protective coating 48. The protective sheet 46and protective coating 48 may be made from a number of differentmaterials, including, without limitation, polymers such as a polyester(e.g., Mylar® polyester film), non-poled polyvinylidene fluoride,polyimide (e.g., Kapton® polyimide film), polycarbonate, high-densitypolyethylene, or combinations thereof. The protective sheet 46 and theprotective coating 48 may be the same or different protective material.

FIG. 4 illustrates a top view of a sensor strip 50 that comprises aplurality of the film-based sensors 38 in accordance with presentembodiments. As illustrated, the sensor strip 50 comprises a flexiblesubstrate 52 and the film-based sensors 38. The film-based sensors 38may be spaced regularly or irregularly on the flexible substrate 52. Inparticular embodiments, the sensor strip 50 may be wrapped or weavedthroughout a streamer (e.g., reconfigurable seismic streamer 30). By wayof example, the sensor strip 50 could be positioned so that thefilm-based sensors 38 may be positioned along all three axes of thereconfigurable seismic streamer 30 (see, e.g., seismic sensors 24 onFIG. 11). Each of the film-based sensors 38 may comprise a pair ofelectrical connections 54 for coupling the upper conductive layer 42 andthe lower conductive layer 44 (e.g., see FIG. 3) to wires (not shown) orother suitable mechanism for signal transmission. The configuration ofthe sensor strip 50 shown on FIG. 4 is merely illustrative and use ofalternative configurations for the sensor strip 50 is within the scopeof the present disclosure.

FIG. 5 is another view of the reconfigurable seismic streamer 30 of FIG.2 in accordance with present embodiments. As illustrated, thereconfigurable seismic streamer 30 comprises a plurality of seismicsensors 24 distributed throughout a volume of the reconfigurable seismicstreamer 30. In particular embodiments, the seismic sensors 24 maycomprise piezoelectric sensors, such as the film-based sensor 38 shownon FIG. 3, or MEMS sensors. In some embodiments, the seismic sensors 24may be configured in one or more strips of sensors (e.g., sensor strip50 on FIG. 4) or otherwise woven together to form one or moreinterconnected groups of sensors.

In accordance with present embodiments, the seismic sensors 24 of thereconfigurable seismic streamer 30 may be assigned to one or moresampling groups 56, 58, 60, 62. In the illustrated embodiment, foursampling groups 56, 58, 60, 62 are shown but the seismic sensors 24 maybe assigned to more or less than four sampling groups as desired for aparticular application. The sampling groups 56, 58, 60, 62 may bereferred to as first sampling group 56, second sampling group 58, thirdsampling group 60, and fourth sampling group 62. The signals of theseismic sensors 24 in each sampling group may be summed or otherwisecombined for data processing. Signal combination may occur before orafter digitizing of the signal. As illustrated by FIG. 5, the groupspacing may overlap in some embodiments. For example, one or more of theseismic sensors 24 in a particular sampling group may also be assignedpartially to the immediately preceding group or immediately followinggroup. To partially assign, particular one of the seismic sensors 24 tomore than one of the sampling groups 56, 58, 60, 62, for example, thesignal may be duplicated, weighted (such that the total weight is still1), and then distributed over adjacent sampling groups. In someembodiments, the contribution of the overlapping sensors in each groupmay be weighted in each group based on the distance to the center of theparticular group. In the illustrated embodiment, the first group 56 andthe second group 58 contain overlapping sensors. For example, a portionof the seismic sensors 24 assigned to the first group 56 may also beassigned to the second group 58, and a portion of the seismic sensors 24assigned to the second group 58 may also be assigned to the first group56. While only the first group 56 and the second group 58 are shown withoverlapping sensors, other of the seismic sensors 24 may be assigned tooverlapping groups in accordance with present embodiments.

In some embodiments, the group spacing (d₁) and/or group overlap (d₂)may vary based on a particular criteria. For example, the group spacing(d₁) may be varied based on expected signal-to-noise ratio. Signals ofinterest may be lower in amplitude in deeper water due to their laterarrivals and due to practical or environmental limits imposed on sourcestrengths, for example. Accordingly, it may be beneficial to have anincreased group spacing (d₁) in particular embodiments. For example, thegroup spacing may be increased to 15 meters or even longer (18.75 m)from the standard group spacing of 12.5 meters. In other embodiments,the seismic sensors 24 may be assigned to sampling groups in subsequentprocessing that have a group spacing (d₁) that is a factor (e.g., x/2,x/3, x/6, x/8, x/10, etc.) of the shot spacing.

In some embodiments, the sampling groups 56, 58, 60, 62 may bereconfigured, for example, to account for streamer stretch. By way ofexample, the centers of the sampling groups 56, 58, 60, 62 may beredefined during data acquisition based on actual distance along thereconfigurable seismic streamer 30 instead of adapting their offsetsaccordingly. By way of example, if the seismic sensors 24 aredistributed linearly along the reconfigurable seismic streamer 30 andthe fourth sampling group 62 is displaced 10 meters further along due tostretch, then some seismic sensors 24 could be removed from the fourthsampling group 62 and other of the seismic sensors 24 could be added tothe fourth sampling group 62 based on their actual distance along thereconfigurable seismic streamer 30 in relation to the group center.

FIGS. 6 and 7 show alternative embodiments of the reconfigurable seismicstreamer 30 with different sampling group configurations. As illustratedby FIG. 6, the sampling groups 56′, 58′, 60′, 62′ may have an irregularspacing in some embodiments. As illustrated by FIG. 7, the seismicsensors 24 may become less dense from the front of the reconfigurableseismic streamer 30 its end such that the number of the seismic sensors24 in each of the sampling groups 56″, 58″, 60″, 62″ varies.

FIG. 8 is a three-dimensional view of the reconfigurable seismicstreamer 30 of FIG. 5 illustrating the seismic sensors 24 distributedthroughout a volume thereof in accordance with present embodiments. Thex-, y-, and z-axes of the reconfigurable seismic streamer 30 are shownon FIG. 8. As illustrated, the seismic sensors 24 may be distributed inthe volume of the reconfigurable seismic streamer 30 on the x-axis andthe y-axis. The seismic sensors 24 shown on FIG. 8 may be distributedalong the z-axis of the reconfigurable seismic streamer 30 a depth ofZ₁. With additional reference to FIG. 9, the seismic sensors 24 may alsobe distributed on the z-axis of the reconfigurable seismic streamer 30.

FIG. 10 is a cross-sectional view of the reconfigurable seismic streamer30 of FIG. 5, in accordance with present embodiments, having seismicsensors 24 distributed throughout a volume thereof. As illustrated, oneor more of the seismic sensors 24 may be on the surface of thereconfigurable seismic streamer 30. The seismic sensors 24 shown on FIG.10 may not necessarily be in the slice itself but could be distributedin the reconfigurable seismic streamer 30 at different z-positions. Inthe illustrated embodiment, the center of the reconfigurable seismicstreamer 30 is represented by reference number 64. As indicated in FIG.10, directional derivatives may be determined from finite differencecalculations by using weights based on projected distances along andperpendicular to a particular direction, indicated by arrow 66. Based onfinite difference calculation, the directional derivatives in all threeaxes may be determined by using, for example, contributions from theseismic sensors 24 located around the cylindrical surface of thereconfigurable seismic streamer 30 and their perpendicular distance tothe cross-section shown. Accordingly, several orders of directionalderivatives along or orthogonal (or in other directions) to thereconfigurable seismic streamer 30 may be determined. The directionalderivatives may be determined even if at least some of the seismicsensors 24 are not necessarily located in line with a certain directionof the derivatives.

FIG. 11 is a view of a reconfigurable seismic streamer 30′ illustratingone embodiment for distribution of the seismic sensors 24 throughout avolume thereof. In particular embodiments, the seismic sensors 24 maycomprise piezoelectric sensors, such as the film-based sensor 38 shownon FIG. 3. The reconfigurable seismic streamer 30′ may be used inseismic surveying, such as in the marine geophysical survey system 16illustrated on FIG. 2.

As illustrated, the reconfigurable seismic streamer 30′ may include aplurality of seismic sensors 24 distributed throughout the volume andalong all three axes of the reconfigurable seismic streamer 30′. In theillustrated embodiment, the seismic sensors 24 are distributed along thereconfigurable seismic streamer 30′ in helical patterns. In particularembodiments, four different sensor strips 50 a-50 d containing theseismic sensors 24 are distributed in helical patterns along and aboutthe longitudinal (or z-axis) of the reconfigurable seismic streamer 30′.The seismic sensors 24 in each of the sensor strips 50 a-50 d may bewoven together or otherwise coupled so that each of the sensor strips 50a-50 d forms an interconnected strip of the seismic sensors 24. Anexample of such an interconnected strip is the sensor strip 50 shown onFIG. 4 on which the seismic sensors 24 comprise film-based sensors 38.As illustrated, the sensor strips 50 a-50 d may be arranged so that atleast two of the seismic sensors 24 are diametrically opposed and thereare at least four of the seismic sensors 24 in a cross-section. Forexample, seismic sensors 24 a and 24 c may be diametrically opposed toone another while seismic sensors 24 a-24 d may each be in the samecross-section. In this arrangement, the seismic sensors 24 on the sensorstrips 50 a-50 d may each be spaced on the corresponding sensor strips50 a-50 d at common intervals to provide two of the seismic sensors 24that are diametrically opposed to one another with four of the seismicsensors in a cross-section.

FIG. 12 is another view of a reconfigurable seismic streamer 30″illustrating one embodiment for distribution of the seismic sensors 24throughout a volume thereof. In particular embodiments, the seismicsensors 24 may comprise piezoelectric sensors, such as the film-basedsensor 38 shown on FIG. 3. The reconfigurable seismic streamer 30″ maybe used in seismic surveying, such as in the marine geophysical surveysystem 16 illustrated on FIG. 2. As illustrated, the seismic sensors 24may be distributed over and around a surface of the reconfigurableseismic streamer 30″, which may be an interior or exterior surface. Inthe illustrated embodiment, the seismic sensors 24 may be distributedover and around a core 72 of the reconfigurable seismic streamer 30″. Inthe illustrated embodiment, two sensors strips 50 e and 50 f comprisingthe seismic sensors 24 are shown weaving over and around the core 72.The seismic sensors 24 in each of the sensor strips 50 e and 50 f may bewoven to together or otherwise coupled so that each of the sensor strips50 e and 50 f forms an interconnected strip of the seismic sensors 24.An example of such an interconnected strip is the sensor strip 50 shownon FIG. 4 on which the seismic sensors 24 comprise film-based sensors38. Similar to the embodiment illustrated on FIG. 11, the sensor strips50 e and 50 f shown on FIG. 12 may also be arranged so that the two ofthe seismic sensors 24 are diametrically opposed to one another. Forexample, seismic sensors 24 e and 24 f may be diametrically opposed toone another as illustrated on FIG. 11.

Although specific embodiments have been described above, theseembodiments are not intended to limit the scope of the presentdisclosure, even where only a single embodiment is described withrespect to a particular feature. Examples of features provided in thedisclosure are intended to be illustrative rather than restrictiveunless states otherwise. The above description is intended to cover suchalternatives, modifications, and equivalents as would be apparent to aperson skilled in the art having the benefit of this disclosure.

The scope of the present disclosure includes and feature or combinationof features disclosed herein (either explicitly or implicitly), or anygeneralization thereof, whether or not it mitigates any or all of theproblems addressed herein. Various advantages of the present disclosurehave been described herein, but embodiments may provide some, all, ornone of such advantages, or may provide other advantages.

What is claimed is:
 1. A system, comprising: a sensor cable; seismicsensors distributed throughout a volume of the sensor cable and alongall three axes of the sensor cable, wherein the seismic sensors arespaced regularly or irregularly on two or more sensor strips, whereinthe seismic sensors are assigned to sampling groups that arereconfigurable and not hardwired, wherein the seismic sensors aredistributed throughout the volume of the sensor cable, wherein the twoor more sensor strips are arranged along the sensor cable in helicalpatterns; and a computer system configured to: determine directionalderivatives in all three axes of the sensor cable using contributionsfrom two or more of the seismic sensors that are not located in linewith a direction of the directional derivatives, wherein the two or moreof the seismic sensors are distributed in the sensor cable at differentx-, y-, and/or z-positions, wherein the directional derivatives aredetermined from finite difference calculations by using weights based onprojected distances along and perpendicular to a particular direction;reconfigure the sampling groups; and if one of the seismic sensorsfails, then reweight the contributions of adjacent seismic sensors tocompensate for the failure.
 2. The system of claim 1, wherein at leastone of the seismic sensors comprises a piezoelectric sensor.
 3. Thesystem of claim 2, wherein the piezoelectric sensor comprises afilm-based sensor or a MEMS sensor.
 4. The system of claim 1, wherein atleast a portion of the sensors are disposed on a sensor strip.
 5. Thesystem of claim 1, wherein at least two of the seismic sensors in across-section are diametrically opposed to one another while there areat least four of the seismic sensors in the cross-section.
 6. The systemof claim 1, wherein density of the seismic sensors distributedthroughout the volume of the sensor cable decreases from the front ofthe sensor cable to the rear of the sensor cable.
 7. The system of claim1, wherein at least one of the seismic sensors comprises a film, thefilm comprising a viscoelastic polymer and a piezoelectric ceramic. 8.The system of claim 1, wherein the sensor cable is a streamer or anocean bottom cable.
 9. The system of claim 1, wherein the computersystem is configured to receive geophysical data from the seismicsensors and assign the seismic sensors to overlapping sampling groups.10. The system of claim 1, wherein the computer system is configured toreceive geophysical data from the seismic sensors and assign the seismicsensors to sampling groups that have irregular spacing.
 11. The systemof claim 1, wherein the computer system is configured to receivegeophysical data from the seismic sensors and redefine group centers ofthe sampling groups based on actual distance of the seismic sensorsalong the sensor cable.
 12. An apparatus, comprising: a sensor cable;seismic sensors distributed throughout a volume of the sensor cable andat different positions along all three axes of the sensor cable, whereinat least one of the seismic sensors is a film-based sensor, wherein thefilm-based sensor comprises a film, the film comprising a viscoelasticpolymer and a piezoelectric ceramic, wherein at least one of the seismicsensors further comprises an upper conductive layer and a lowerconductive layer, the upper conductive layer and the lower conductivelayer being on opposing sides of the film, and wherein the at least oneof the seismic sensors further comprises a protective coating disposedon the upper conductive layer, and wherein the film, the upperconductive layer, and the lower conductive layer are coated on aprotective sheet; and two or more sensor strips comprising more than oneof the seismic sensors disposed on a flexible substrate of the two ormore sensor strips, wherein the seismic sensors are spaced regularly orirregularly on the two or more sensor strips, wherein the two or moresensor strips are wrapped around or weaved throughout at least a portionof the sensor cable in a helical pattern.
 13. The apparatus of claim 12,wherein the piezoelectric ceramic is selected from the group consistingof barium titanate, lead zirconate, and combinations thereof.
 14. Theapparatus of claim 12, wherein the seismic sensors are assigned tosampling groups that are reconfigurable and not hardwired.
 15. A methodcomprising: obtaining geophysical data; processing the geophysical datato generate a geophysical data product, wherein the geophysical data isobtained using seismic sensors distributed throughout a volume of asensor cable and along all three axes of the sensor cable, wherein theseismic sensors are assigned to sampling groups that are reconfigurableand not hardwired, wherein the seismic sensors are spaced regularly orirregularly on two or more sensor strips and the two or more sensorstrips are wrapped around or weaved throughout at least a portion of thesensor cable in a helical pattern; determining directional derivatives,with a computer system, in all three axes of the sensor cable usingcontributions from two or more of the two or more seismic sensors thatare not located in line with a direction of the directional derivatives,wherein the two or more of the seismic sensors are distributed in thesensor cable at different x-, y, and/or z-positions, wherein thedirectional derivatives are determined from finite differencecalculations by using weights based on projected distances along andperpendicular to a particular direction; reconfiguring the samplinggroups; and if one of the seismic sensors fail, then reweighting thecontributions of adjacent seismic sensors to compensate for the failure.16. The method of claim 15, wherein the sensor cable is either towedthrough a body of water or positioned on a water bottom.
 17. The methodof claim 15, further comprising recording the geophysical data producton a tangible, non-volatile computer-readable medium suitable forimporting onshore.
 18. The method of claim 16, further comprisingperforming geophysical analysis onshore on the geophysical data product.19. The method of claim 15, further comprising assigning the seismicsensors to sampling groups that are irregular in length.
 20. The methodof claim 15, further comprising assigning the seismic sensors tosampling groups, wherein two or more of the sampling groups overlap. 21.The method of claim 15, further comprising redefining centers of thesampling groups based on actual distance along the sensor cable, inresponse to stretching of the sensor cable.
 22. A method comprising:actuating one or more seismic sources in a body of water in conjunctionwith a marine seismic survey; and detecting acoustic energy originatingfrom the one or more seismic sources using seismic sensors distributedthroughout a volume of a sensor cable and at different positions alongall three axes of the sensor cable, wherein the seismic sensors arespaced regularly or irregularly on two or more sensor strips, wherein atleast one of the seismic sensors is a film-based sensor, wherein thefilm-based sensor comprises a film, the film comprising a viscoelasticpolymer and a piezoelectric ceramic, wherein more than one of thefilm-based sensor is disposed on the two or more sensor strips, the twoor more sensor strips comprising a flexible substrate on which the morethan one of the film-based sensor is disposed, wherein the two or moresensor strips are wrapped around or weaved in a helical patternthroughout at least a portion the sensor cable.
 23. The method of claim22, wherein the at least one of the seismic sensors further comprises anupper conductive layer and a lower conductive layer, the upperconductive layer and the lower conductive layer being on opposing sidesof the film, and wherein the at least one of the seismic sensors furthercomprises a protective coating disposed on the upper conductive layer,and wherein the film, the upper conductive layer, and the lowerconductive layer are coated on a protective sheet.
 24. The method ofclaim 22, wherein at least a portion of the seismic sensors are disposedon one of the two or more sensor strips.
 25. The method of claim 22,further comprising assigning the seismic sensors to sampling groups thatare reconfigurable and not hardwired.